JUNE 30, 2020 | WEBEX

Assumptions for Calculating the Installed Capacity Requirement and Related Values for the 2024-2025 Forward Capacity Auction (FCA 15)

Power Supply Planning Committee Meeting

Manasa Kotha SENIOR ENGINEER, RESOURCE STUDIES AND ASSESSMENTS

ISO-NE PUBLIC Objective of this Presentation

• Review the assumptions used in the development of the Installed Capacity Requirement (ICR) and related values*: – Transmission Security Analysis (TSA) – Local Resource Adequacy Requirement (LRA) – Local Sourcing Requirement (LSR) – Maximum Capacity Limit (MCL) – Marginal Reliability Impact Demand Curves (MRI Demand Curves) – Hydro Quebec Installed Capability Credits (HQICCs)

*The ICR, LSR, MCL, the MRI Demand Curves and HQICCs are collectively referred to as the ICR- Related Values

ISO-NE PUBLIC 2 Modeling the New England Control Area for FCA 15 • The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related Values • Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus – Internal transmission constraints are addressed through the LSR and MCLs • A LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA and RI Load Zones • MCLs will be calculated for two export-constrained Capacity Zones: the Maine Capacity Zone and the Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New Hampshire and Vermont – The Maine Capacity Zone will be nested in the NNE Capacity Zone • The MRI based method for calculating demand curves will be used to develop System and Capacity Zone Demand Curves

Note: For more info on the development of FCA 15 Capacity Zones, see https://www.iso-ne.com/static- assets/documents/2020/05/a05_pspc_2020_05_28_fca_15_cap_zone_formation.pdf

ISO-NE PUBLIC 3 ASSUMPTIONS FOR THE 2024-2025 FCA ICR-RELATED VALUES CALCULATIONS

ISO-NE PUBLIC 4 Cost of New Entry (CONE) - for the MRI Demand Curve • CONE for the cap of the MRI system Demand Curve for FCA 15 has been calculated as: – Gross CONE: $11.951/kW-month – Net CONE : $8.707/kW-month – FCA Starting Price : $13.932/kW-month

*See link to Forward Capacity Market (FCM) parameters by Capacity Commitment Period: https://www.iso- ne.com/static-assets/documents/2015/09/FCA_Parameters_Final_Table.xlsx

ISO-NE PUBLIC 5 Assumptions for the ICR-Related Values Calculations • Load forecast – Net of behind-the-meter (BTM) photovoltaic (PV) forecast – Transportation and heating electrification – Load forecast distribution • Resource data will be based on qualified existing capacity values for FCA 15 – Non-Intermittent Generating Resources – Intermittent Power Resources (IPR) – Import Capacity Resources – Demand Capacity Resources • These qualified capacity values reflect – Significant decrease of existing qualified resources – Resource retirements and terminations • Permanent and Retirement De-List Bids elected unconditional treatment and that are at or above the FCA 15 Starting Price

ISO-NE PUBLIC 6 Assumptions for the ICR-Related Values Calculations, cont. • Resource availability – Non-Intermittent Generating Resources availability – IPR availability – ADCR availability • Load relief from Operating Procedure No. 4, Action During a Capacity Deficiency (OP-4) actions – Tie reliability benefits • Quebec • Maritimes • New York – 5% voltage reduction

ISO-NE PUBLIC 7 Load Forecast Data

• Load forecast assumption from the 2020 Forecast Report of Capacity, Energy, Loads and Transmission (CELT) load forecast* • The load forecast weather-related uncertainty is represented by specifying a series of multipliers on the peak load and the associated probabilities of each load level occurring – The multipliers used to describe the load forecast uncertainty are derived from the 52 weekly peak load distributions described by the expected value (mean), the standard deviation and the skewness

*The 2020 CELT load forecast is available at https://www.iso-ne.com/static- assets/documents/2020/04/2020_celt_report.xlsx

ISO-NE PUBLIC 8 Load Forecast Data, cont. Modeling of BTM PV

• FCA 15 ICR calculations will use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static- assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdf – Used for all probabilistic ICR-Related Values calculations – Modeled in GE MARS by groupings using the Regional System Plan (RSP) 13-subarea representation – Includes an 8% transmission and distribution gross-up – Peak load reduction uncertainty is modeled (randomly selected by MARS from a seven day window distribution) • The values of BTM PV published in the 2020 CELT Report are the values of BTM PV subtracted from the gross load forecast to determine the net load forecast • The published 90/10 net load forecast for the SENE sub-areas is used in the TSA

Notes: For more info on the PV forecast, see https://www.iso-ne.com/static-assets/documents/2020/04/final_2020_pv_forecast.pdf

ISO-NE PUBLIC 9 Load Forecast Data, cont. Modeling of Transportation and Heating Electrification Transportation Electrification – The ICR and Related Values calculations will use an hourly profile for transportation electrification forecast • Includes an 8% transmission and distribution gross-up • Uncertainty is currently not modeled due to lack of performance data – More information on the development of the transportation electrification forecast can be found at : https://www.iso-ne.com/static- assets/documents/2020/04/final_2020_transp_elec_forecast.pdf Heating Electrification – The ICR and Related Values calculations will use the 2020 CELT gross load forecast that include the heating electrification loads which occur during the winter months • The hourly gross load forecast (2020 Forecast Data workbook) is inclusive of heating electrification forecast. The heating electrification loads are weather sensitive and therefore, the uncertainties relating to weather also apply to these loads – More information on the development of the heating electrification forecast can be found at : https://www.iso-ne.com/static- assets/documents/2020/04/final_2020_heat_elec_forecast.pdf

ISO-NE PUBLIC 10 Load Forecast Data, cont. New England System Load Forecast

Monthly Peak Load (MW) - Net of BTM PV

CCP JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY 2024-2025 26,095 28,202 27,426 24,068 19,507 21,190 23,094 24,073 23,383 21,571 19,488 22,756

• Corresponds to the reference forecast labeled “ISO-NE Control Area & New England States Monthly Peak Load Forecast“ from worksheet “4 Mnth Peak” of the 2020 Forecast Data • https://www.iso-ne.com/static-assets/documents/2020/04/forecast_data_2020.xlsx

Probability Distribution of Seasonal Peak Load (MW)

10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/5 Summer 2024 27,771 28,202 28,581 28,933 29,303 29,836 30,251 30,667 31,377 31,889 Winter 2024-25 23,958 24,073 24,158 24,255 24,329 24,464 24,634 24,814 25,020 25,195

• From Table 1.6 - Seasonal Peak Load Forecast Distributions (forecast is reference with reduction for BTM PV) of the 2020 CELT • https://www.iso-ne.com/static-assets/documents/2020/04/2020_celt_report.xlsx

ISO-NE PUBLIC 11 Resource Data – Generating Capacity Resources (MW)

Non-Intermittent Generating Resource Intermittent Resource Total Load Zone

Summer Winter Summer Winter Summer Winter MAINE 2844.953 3026.457 281.313 329.956 3126.266 3356.413 NEW HAMPSHIRE 4152.612 4306.116 82.170 161.120 4234.782 4467.236 VERMONT 206.814 245.674 64.118 107.785 270.932 353.459 CONNECTICUT 9741.155 10183.737 120.887 99.409 9862.042 10283.146 RHODE ISLAND 1826.126 2025.848 47.318 41.508 1873.444 2067.356 SOUTH EAST MASSACHUSETTS 4460.967 4763.884 289.751 357.617 4750.718 5121.501 WEST CENTRAL MASSACHUSETTS 3740.827 3984.596 173.579 109.119 3914.406 4093.715 NORTH EAST MASSACHUSETTS & BOSTON 1296.241 1399.331 54.483 43.609 1350.724 1442.940 Total New England 28269.695 29935.643 1113.619 1250.123 29383.314 31185.766

Qualified Existing Generating Capacity Resources for FCA 15 reflect: • Significant decreases • Resource retirements and known terminations • Unconditional Permanent and Retirement De-List Bids • Permanent De-List Bids that are at or above the FCA 15 Starting Price • IPR have both summer and winter values modeled; Non-Intermittent Generating Resources winter values provided for informational purpose

ISO-NE PUBLIC 12 Resource Data – Import Capacity Resources (MW)

Import Resource Summer MW External Interface NYPA - CMR 68.000 New York AC Ties NYPA - VT 14.000 New York AC Ties Total MW 82.000

• Qualified Existing Import Capacity Resources for FCA 15 • The NYPA supplied Import Capacity Resources’ performance (availability) will be modeled with the performance assumptions associated with the New York AC ties

ISO-NE PUBLIC 13 Resource Data – Demand Capacity Resources (MW)

Seasonal Peak Demand Active Demand Capacity On-Peak Demand Resource Total Load Zone Resource Resource (ADCR) Summer Winter Summer Winter Summer Winter Summer Winter MAINE 224.411 201.876 - - 137.803 155.699 362.214 357.575 NEW HAMPSHIRE 136.625 134.384 - - 48.408 47.688 185.033 182.072 VERMONT 111.485 111.751 - - 51.904 57.510 163.389 169.261 CONNECTICUT 130.311 68.194 561.440 635.793 192.829 192.123 884.580 896.110 RHODE ISLAND 270.390 281.671 - - 44.736 41.207 315.126 322.878 SOUTH EAST MASSACHUSETTS 463.678 467.793 - - 56.954 55.126 520.632 522.919 WEST CENTRAL MASSACHUSETTS 476.249 490.808 20.010 3.616 112.074 108.419 608.333 602.843 NORTH EAST MASSACHUSETTS & BOSTON 727.791 712.015 - - 99.906 100.007 827.697 812.022 Grand Total 2540.940 2468.492 581.450 639.409 744.614 757.779 3867.004 3865.680

• Qualified Existing Demand Resources for FCA 15 • Includes the 8% transmission and distribution loss adjustment (gross-up)

ISO-NE PUBLIC 14 Capacity Zone Resource Breakdown and 50/50 & 90/10 Peak Load Forecast Assumptions Used in LRA and MCL Calculations (MW)

Resource Type SENE NNE Maine New England Non-Intermittent Generating Resource 7,583 7,204 2,845 28,270 Intermittent Resource 392 420 281 1,114 Import Resource - - - 82 On-Peak Demand Resource 1,482 465 221 2,541 Seasonal-Peak Demand Resource 1 - - 581 Active Demand Capacity Resource 207 235 136 745 Total Capacity 9,665 8,324 3,483 33,332

SENE NNE Maine New England 50/50 Load Forecast Net BTM PV 12,679 5,645 2,230 29,303 90/10 Load Forecast Net BTM PV 13,739 5,908 2,332 31,377

• An LSR will be calculated for the SENE Capacity Zone; MCLs will be calculated for the Maine and NNE Capacity Zones • Zonal requirements will be determined using the load forecast and resource assumptions for the identified Capacity Zones for FCA 15 • The 50/50 and 90/10 load forecast values for the Capacity Zones will be the sum of the appropriate RSP sub-areas and are shown for informational purposes • Note that the values are presented based on RSP subarea

ISO-NE PUBLIC 15 LRA, TSA & MCL Internal Transmission Transfer Capability Assumptions

• Maine - New Hampshire Export – N-1 Limit: 1,900 MW • Northern New England Export (North-South interface) – N-1 Limit: 2,725 MW • Southeast New England Import – N-1 Limit: 5,150 MW – N-1-1 Limit: 4,300 MW

Note: Based on transmission transfer capability limits presented at the March, 2020 Reliability Committee meeting. The presentation is available at: https://www.iso-ne.com/static-assets/documents/2020/03/a08.0_rc_2020_03_17_presentation.pdf

ISO-NE PUBLIC 16 Availability Assumptions - Non-Intermittent Generating Resources • Forced outages assumption – Each generating unit’s Equivalent Forced Outage Rate on Demand (non- weighted EFORd) will be modeled – Based on a 5-year average (January 2015 – December 2019) of Generation Availability Data System (GADS) data submitted by generators – NERC GADS class average data will be used for immature/non- commercial units • Scheduled outage assumption – Each generating unit’s weeks of maintenance modeled – Based on a 5-year average (January 2015 – December 2019) of each generator’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance – NERC GADS class average data will be used for immature/non- commercial units

ISO-NE PUBLIC 17 Availability Assumptions - Non-Intermittent Generating Resources

Average EFORd Average Maintenance Resource Category Summer MW (%) Weighted by Weeks Weighted by Summer Ratings Summer Ratings

Combined Cycle 13,222 4.1 4.8 Fossil 5,030 15.4 5.4 Combustion Turbine 3,463 10.2 2.6 Nuclear 3,326 1.2 3.1 Hydros (includes pumped Storage) 3,050 2.1 5.4 Diesel 115 8.3 2.3 Miscellaneous 63 13.1 5.7 Total 28,270 6.4 4.5

• Average summer MW weighted EFORd and maintenance weeks are shown by resource category for informational purposes. In the LOLE simulations used for determining ICR and Related Values, individual unit assumptions will be modeled.

ISO-NE PUBLIC 18 Availability Assumptions - IPR

• Modeled as 100% available since their outages have been incorporated in their 5-year historical output used in calculating their existing Qualified Capacity

ISO-NE PUBLIC 19 Availability Assumptions – Demand Resources

On-Peak Demand Seasonal Peak Demand Active Demand Capacity Total Resource Resource Resource Load Zone Summer Performance Summer Performance Summer Performance Summer Performance (MW) (%) (MW) (%) (MW) (%) (MW) (%) MAINE 224 100 - - 138 100 362 100 NEW HAMPSHIRE 137 100 - - 48 98 185 99 VERMONT 111 100 - - 52 98 163 99 CONNECTICUT 130 100 561 100 193 97 885 99 RHODE ISLAND 270 100 - - 45 85 315 98 SOUTH EAST MASSACHUSETTS 464 100 - - 57 94 521 99 WEST CENTRAL MASSACHUSETTS 476 100 20 100 112 91 608 98 NORTH EAST MASSACHUSETTS & BOSTON 728 100 - - 100 88 828 99 Total New England 2,541 100 581 100 745 95 3,867 99 • DR average performance percentages will be applied to FCA 15 qualified Existing DR • Average of 2015 – 2019 historical summer and winter DR performance • Modeled as a forced outage rate of 1-performance in blocks by DR type and Load Zone • Historical DR performance in ICR – FCA 12 total New England DR modeled was 3,211 MW at 98% – FCA 13 was 3,502 MW at 99% – FCA 14 was 3,859 MW at 99%

Note: For calculation details on ADCR Availability (performance), see https://www.iso-ne.com/static- assets/documents/2020/05/a04_pspc_dr_avail_assumptions_icr.pdf

ISO-NE PUBLIC 20 Availability Assumptions – Import Capacity Resources • System Import Capacity Resources – The forced and planned outage assumptions will be based on the availability assumptions associated with the transmission line used to import the capacity resource. The following table shows the availability assumptions updated for the external ties based on the new proposed methodology for developing external tie lines’ forced and scheduled outage rates:

Forced Outage Maintenance External Ties Rate (%) (Weeks)

Cross Sound Cable 0 3.4 Highgate 0 0.9 HQ Phase II 1.3 2.9 New Brunswick Ties 0.1 2.6 New York AC Ties 0.5 5.9

• Unit/plant Import Capacity Resources – The forced and planned outage assumptions will be based on the assumptions associated with the unit/plant supplying the import capacity

ISO-NE PUBLIC 21 Availability Assumptions – Tie Benefits • Annual maintenance weeks and forced outage rates associated with the external transmission ties are applied to their corresponding tie benefit assumptions. These maintenance weeks and forced outage rates are developed based on each tie line’s 5-year (2015- 2019) historical rolling average performance data – These assumptions are calculated using the methodology established in 2019 https://www.iso-ne.com/static- assets/documents/2019/05/a5_tie_line_availability_05302019.pdf

New Brunswick Cross Sound Cable Highgate HQ Phase II New York AC Ties Ties FCA 14 FCA 15 FCA 14 FCA 15 FCA 14 FCA 15 FCA 14 FCA 15 FCA 14 FCA 15 Annual maintenance requirement (weeks) 6 3.4 1.2 0.9 3.2 2.9 3.2 2.6 5.3 5.9

Annual forced outage rate (%) 0 0 0.1 0 0.9 1.3 0 0.1 0.5 0.5

Note: These are the same values used to model the performance of the Import Capacity Resources that are system based as shown in previous slide

ISO-NE PUBLIC 22 OP-4 Assumptions Action 6 & 8 - 5% Voltage Reduction (MW)

Actions 6 & 8 90-10 Peak Load 5% Voltage (Net BTMPV) Passive DR ADCR Reduction June 2024-Sept 2024 31,377 3,122 745 275 October 2024-May 2025 25,020 3,108 758 212

Note:

• Uses the 90-10 peak Gross load (including both transportation and heating electrification forecast) forecast minus BTM PV and all passive DR and ADCR

• Multiplied by the 1.0% estimated relief obtainable from OP-4 voltage reduction

ISO-NE PUBLIC 23 OP-4 Assumptions, cont. Minimum Operating Reserve Requirement (MW)

• The system reserves assumption will be consistent with those needed for reliable system operations during Emergency Conditions • Modeled at 700 MW in the ICR calculations

ISO-NE PUBLIC 24 Summary of all MW Modeled in the ICR-Related Values Calculations

Resource Type/OP-4 FCA 15 Non-Intermittent Generating Resource 28,270 Intermittent Power Resource 1,114 Import Capacity Resource 82 Demand Resource 3,867 OP-4 voltage reduction 275 Minimum Operating Reserves -700 Tie benefits TBD Total MW modeled in ICR TBD Notes:

• TBD = To be determined

• The tie benefits assumptions will be updated based on the study

• IPRs have both the summer and winter capacity values modeled

• OP-4 voltage reduction includes both Action 6 and Action 8 MW assumptions

ISO-NE PUBLIC 25 ISO-NE PUBLIC 26 APPENDIX Acronyms for ICR-Related Values*

*Not all acronyms are used in this presentation

ISO-NE PUBLIC 27 Acronyms • ADCR – Active Demand Capacity Resource • ALCC – Additional Load Carrying Capability • APk – Gross peak load net of BTM PV • ARA – Annual Reconfiguration Auction • ART – Annual Reconfiguration Transaction • BTM PV – Behind-the-meter Photovoltaic • CCP – Capacity Commitment Period • CDD – Cooling Degree Days • CELT – Capacity, Energy, Loads and Transmission • CSC – Cross Sound Cable • CSO – Capacity Supply Obligation • CT – Connecticut • DR – Demand Resource • EE – Energy Efficiency • EFORd – Equivalent Forced Outage Rate on Demand

ISO-NE PUBLIC 28 Acronyms, cont. • FCA – Forward Capacity Auction • FCM – Forward Capacity Market • FERC – Federal Energy Regulatory Commission • HQICCs – Hydro-Quebec Interconnection Capability Credits • ICR – Installed Capacity Requirement • ISO – ISO New England • LRA – Local Resource Adequacy • LSR – Local Sourcing Requirement • MARS -Multi-Area Reliability Simulation • MCL – Maximum Capacity Limit • MRI – Marginal Reliability Impact • NEPOOL – New England Power Pool • Net ICR – ICR minus HQICCs • NNE – Northern New England

ISO-NE PUBLIC 29 Acronyms, cont. • NPCC – Northeast Power Coordinating Council • OP-4 – Operating Procedure No. 4, Action During a Capacity Deficiency • PAC – Planning Advisory Committee • PC – Participants Committee • PK – Peak (gross load forecast) • PSPC – Power Supply Planning Committee • RC – Reliability Committee • RI – Rhode Island • SEMA – Southeastern Massachusetts • SENE – Southern New England • SWCT – Southwest Connecticut • TSA – Transmission Security Analysis • VR – Voltage Reduction • WEFORd – Weighted Equivalent Forced Outage Rated on Demand

ISO-NE PUBLIC 30